Method of increasing enhanced oil recovery by using a novel low sulfonate phase in the polymer slug

ABSTRACT

This invention relates to a process for enhanced recovery of hydrocarbons from a subterranean hydrocarbon-bearing formation penetrated by an injection well and a production well wherein, before injection, the surfactant fluid is separated into two phases by the addition of small amounts of polymer and the portion having the higher sulfonate content is used as the surfactant slug. As an improvement we disclose the step of adding the phase of surfactant fluid with the lower sulfonate content to the polymer slug which is used to drive the surfactant fluid to further increase recovery.

CROSS-REFERENCE TO RELATED APPLICATION

This application is related to U.S. patent application Ser. No.06/729,452, filed of even date, which is concerned with a method forenhanced hydrocarbon recovery wherein a polymer is dissolved in fluidresulting from mixing water, sulfonate-containing surfactant andsolubilizer, allowing the mixture to separate and using the fractionwith the highest sulfonate content as the surfactant fluid.

FIELD OF THE INVENTION

This invention relates to a process for enhanced recovery ofhydrocarbons from a subterranean hydrocarbon-bearing formationpenetrated by an injection well and a production well wherein, beforeinjection, the surfactant fluid is separated into two phases by theaddition of small amounts of polymer and the portion having the highersulfonate content is used as the surfactant slug. As an improvement, wedisclose a method of adding the phase of surfactant mixture with thelower sulfonate content to the polymer slug which is used to drive thesurfactant fluid, to further increase recovery.

BACKGROUND OF THE INVENTION

This invention relates to surfactant flooding fluids for the enhancedrecovery of petroleum from porous subterranean reservoirs.

The petroleum industry has long recognized that only a fraction of theoriginal oil in a reservoir is expelled by natural mechanisms or primaryproduction. Accordingly, there is a need for improved methods ofincreasing the ultimate yield of petroleum from natural reservoirs. Manylarge reserves of petroleum fluids from which only small recoveries havebeen realized by present commercial recovery methods are yet to reach apotential recovery approaching their estimated oil-in-place.

The production of petroleum products is usually accomplished by drillinginto a hydrocarbon-bearing formation and utilizing one of the well-knownrecovery methods for the recovery of hydrocarbons. However, it isrecognized that these primary recovery techniques may recover only aminor portion of the petroleum products present in the formationparticularly when applied to reservoirs of viscous crudes. Even the useof improved recovery practices involving heating, miscible flooding,water flooding and steam processing may still leave up to 70-80 percentof the original hydrocarbons in place.

Water flooding is one of the more widely practiced secondary recoverymethods. A successful water flood may result in recovery of 30-50percent of the original hydrocarbons left in place. However, generallythe application of water flooding to many crudes results in much lowerrecoveries.

The application of these secondary recovery techniques to depletedformations may leave major quantities of oil-in-place, since the crudeis tightly bound to the sand particles of the formation; that is, thesorptive capacity of the sand for the crude is great. In addition,interfacial tension between the immiscible phases results in entrappingcrude in the pores, thereby reducing recovery. Therefore, methods oftertiary or enhanced recovery have been proposed.

Various additives can be added to the flood water to increase oildisplacement. For instance a surfactant such as a petroleum sulfonatemay be added to the water to lower the interfacial tension between oiland water. If enough surface active ingredient is added to lower theinterfacial tension sufficiently, then more oil can be displaced from areservoir by the water containing the surfactant than can be displacedby water not containing the surfactant, or surface active agent. Ifaddition of a surface active agent lowers the interfacial tension to avalue of 0.01 dynes per centimeter or lower, then water containing thesurface active agent will displace essentially all of the oil from mostof the reservoir. In contrast water not containing a surfactant willleave an oil saturation in the reservoir usually between 15 and 50percent of the pore volume. Thus, the purpose of adding a surfactantsuch as a petroleum sulfonate to water is to increase the microscopicdisplacement of oil from the volume of the reservoir rock contacted bythe water.

Another additive commonly employed in such fluids is a polymer. Thepurpose of adding polymer to the surfactant fluid is to decrease themobility of the fluid in the reservoir. This increases the volumetricsweep of the surfactant solution or, in other words, allows the solutionto contact a much larger volume of the reservoir than it would withoutthe polymer. The polymer also enhances the formation of an oil bank infront of the surfactant slug. Thus both surfactant and polymer areusually considered required to ensure both good macroscopic andmicroscopic (or volumetric) displacement of oil.

U.S. Pat. No. 4,049,054 discloses a method of preparing a stablesurfactant water flooding fluid comprising contacting a polymer withfresh water in the substantial absence of a salt and thereaftercombining the thus formed polymer solution and a salt solution andfinally adding a surfactant. It is thought the particular steps ofmixing the components provides a more stable mixture for injection.

U.S. Pat. No. 4,252,192 discloses a process for enhanced oil recoveryusing the product obtained by mixing a major proportion of a petroleumoil feed stock, and a minor proportion of an additive, such as anoxygenated hydrocarbon, with SO₃ under sulfonation conditions, mixedwith about 0.5 to 20% of water at about 50° to 150° C. for a relativelybrief period of time and then neutralizing the resultant material with abase.

In many of the enhanced oil recovery methods known in the art, where asurfactant is employed in the flood operation, a generally acceptedpractice is to follow the surfactant solution with a polymer underpressure. Contrary to the intended result, often the polymer does notfollow the same path as the surfactant, tends to "finger" and bypass thesurfactant and therefore much surfactant and potentially recoverable oilis left behind when the polymer is produced. Several reasons for thisare proposed. The necessity of the surfactant in the first place is dueto the immiscibility of water used in waterflooding with the oil whichis supposed to be recovered. However, it is common to add a surfactantto promote water oil miscibility and then follow the solution with apolymer that is not miscible with that surfactant fluid.

In copending U.S. patent application Ser. No. 729,452, a polymer isadded to the brine-sulfonate-solubilizer fluid, the mixture allowed toseparate, and the fraction with the highest sulfonate content used inthe flooding operations. The displacing polymer had a high interfacialtension with the surfactant. By adding the separated surfactant fractionwith the lower sulfonate content to the polymer slug the interfacialtension between the surfactant and polymer slugs was lowered making thedisplacement more efficient.

Using the invention disclosed herein, it is believed that the efficiencyof flood operations employing a surfactant fluid and polymer slug can befurther improved. Some of the disadvantages of the prior art are avoidedand there is an improvement in the percentage of oil produced byenhanced or tertiary recovery.

SUMMARY OF THE INVENTION

These desirable ends are accomplished by the process of the presentinvention for enhanced recovery of hydrocarbons which comprises:

Injecting a surfactant fluid comprising the separated fraction havingthe highest sulfonate content from a mixture of water, petroleumsulfonate surfactant, solubilizer and polymer into a well and thereafteradding the remaining fraction of surfactant fluid which contains thelower sulfonate content to a polymer slug, injecting the polymer slugand forcing said high sulfonate content surfactant slug and subsequentlythe low sulfonate polymer slug through the formation and recovering saidhydrocarbons.

The improvement of this process over that in copending U.S. patentapplication Ser. No. 729,452, is the addition of the fraction containingthe low sulfonate content to the polymer slug for further increases inefficiency of enhanced recovery and increased miscibility of the polymerslug with the surfactant slug.

Other advantages, uses and the like of the present invention will beapparent to those skilled in the art from the following description ofpreferred embodiments thereof, although variations and modifications maybe effected without departing from the spirit and scope of the novelconcepts presented herein.

DETAILED DESCRIPTION

In the narrower practice of the present invention a process for enhancedrecovery of hydrocarbons is disclosed which comprises:

injecting into the well a surfactant fluid comprising about 0.1% toabout 20.0% of total solute by weight petroleum sulfonate surfactant;about 0.1% to about 5% of total solute by weight solubilizer dispersedin the water; about 0.1 to 10% by weight polymer, wherein the surfactantfluid formed is the product of dissolving the polymer in thewater-surfactant-solubilizer fluid, allowing the mixture to separate,separating the fraction with the highest sulfonate content to use as thesurfactant fluid and separating the remaining fraction which containsthe lower sulfonate content to add to the polymer slug, forcing saidhigh sulfonate content surfactant slug, and subsequently the lowsulfonate content containing enriched polymer slug through the formationand recovering said hydrocarbons.

As indicated the surfactant solution employed in the process of thisinvention typically is composed of water or brine, a sulfonate and asolubilizer and a polymer combined, wherein the water, surfactant andsolubilizer are combined, a small amount of polymer is added and themixture is allowed to separate with subsequent use of the fraction withthe highest sulfonate content as the surfactant flood fluid and additionof the fraction with the lower sulfonate content to the polymer slugwhich generally follows the surfactant flood.

A description of the first embodiment of the process is described indetail in copending application Ser. No. 729,452, the specification ofwhich is herein incorporated by reference.

The water employed is usually brine from the reservoir site, but it canbe most any available water including raw tap water, demineralized orsoftened water, deionized water, etc., as well as other forms of water.Generally it is most economical to use brine water from a reservoir;however, certain characteristics of the available brine should beconsidered which might influence the efficiency of the enhanced recoverysystem. For example, some oil field chemicals such as corrosioninhibitors can be detrimental to surfactant flooding; therefore careshould be taken to make sure the reservoir brine is devoid of thesechemicals.

Numerous surfactants or combinations of surfactants may be employed inthe process of the invention. The preferred class of surfactant isdetermined by the formation temperature and the salinity.

The petroleum sulfonates which can be used as surfactants include allcommercial sulfonates and especially useful are surfactants that containmono-poly sulfonate mixtures. The sulfonate surfactants particularlyuseful in this invention have an average molecular weight greater thanabout 300, such as those described in U.S. Pat. Nos. 3,714,062 and3,997,451 which are expressly incorporated by reference herein fordiscussion of sulfonate materials which will act as surfactants.Suitable sulfonate surfactants include petroleum sulfonates whichgenerally include whole to top crude oils, gas oils or other fractionsof a crude oil stream; aliphatic hydrocarbon polymer sulfonates such as,for example, alkaline metal straight chain hydrocarbon polybutene orpolypropylene polymer sulfonates synthetically prepared aromatic polymersulfonates; or polymers with other sulfonate groupings thereonpossessing surfactant characterstics.

An especially preferred sulfonate is one having an average equivalentmolecular weight in the range of from 300 to about 700. Particularlysuitable are surfactants with a molecular weight in the range of from360-420. Very good results have been observed using WITCO® TRSsulfonates which have average equivalent molecular weights of 300-600.

The concentration of the surfactant will generally be within the rangeof 0.1% to 20.0% of total solute by weight and preferably 0.1% to 10.0%weight percent based on the total weight of the surfactant flood fluid.

Solubilizers are employed to keep the surfactants in solution. A largevariety of commercial solubilizers are functional. Suitable solubilizersinclude two sulfated ethoxylated alcohols sold under the trademarksALFONIC® 1412-A and 1412-S by Conoco Chemical Co. Sulfated ethoxylatedsolubilizers are stable where reservoir temperatures do not exceed about50° C. In higher temperature reservoirs, ethoxylated sulfonates arepreferred.

A variety of polymers can be used in the practice of this invention.Polysaccharides and polyacrylamides are among those which will work. Inthe process of the invention small amounts of polymer are added to thewater-surfactant-solubilizer fluid and time is allowed for the polymerto dissolve and for the mixture to separate so the portion with thehighest sulfonate content can be separated and used in flooding. Theoptimally effective amount of polymer to be used can be determined byperforming bottle tests on the premixed sulfonate mixture. To a seriesof bottles containing the sulfonate mixture is added increasingconcentrations of polymer starting at about 0.1% through 10%. Themixtures are allowed to stand for 1 or 2 days. The resultant mixtureswill be one phase then two phases with different proportions of the twophases. A mixture with the fraction with the highest sulfonate contentbeing about 90% of the total mixture works very well. Generally theamount of polymer will range from 100 ppm to 300 ppm and preferablyabout 200 ppm.

Example I of Copending U.S. Ser. No. 729,452 demonstrates in more detailhow the components of the invention are actually mixed and how thefraction with the higher sulfonate content is recognized.

If the process of this invention were used commercially the type oftanks used presently in fields where flooding procedures are takingplace should be suitable to use for mixing large amounts of water,surfactant and solubilizer within the range of proportions discussed,and then adding the appropriate amount of polymer and allowing thesolution to settle. The surfactant phase at the bottom, for example,could be injected and as the upper phase reached the outlet the polymerslug would be mixed with the upper phase and injected. However, iflarger quantities of surfactant were needed the surfactant could bedrawn off the bottom of several tanks and collected in a larger tank.

Polyacrylamides useful in the process of this invention include allcommercial polyacrylamides. Generally the number average molecularweight of the polyacrylamide or partially hydrolyzed polyacrylamide orsalts thereof utilized in this invention and of the alkoxylatedpolyacrylamide or partially hydrolyzed polyacrylamide or salts thereofwill range from about 10,000 to about 2,000,000 or more. Polyacrylamide,partially hydrolyzed polyacrylamide or salts thereof which aremanufactured and sold by a number of chemical manufacturers are preparedby the usual vinyl compound polymerization methods. NAFLO® Fpolyacrylamide works well. It is manufactured by Nalco.

Another class of hydrophilic polymeric water thickening materialssuitable for use in this invention is the polysaccharide compounds, manyof which are readily available commercially. An example is Kelzanpolysaccharide, manufactured by Xanco division of Kelco Corporation andfunctions best as the polymer slug rather than as the polymer added tothe surfactant fluid.

It is essential that the polymer-surfactant solution be thoroughlymixed. Accordingly mixing times of up to 24 hours may be employed.Depending on the efficiency of the mixing systems, times of 24 to 168hours, preferably 24 to 72 hours are satisfactory for settling time.

By practicing the principles of this invention one is able to obtainenhanced oil recovery yields as high as 99% from core samples, comparedto typically lower yields obtained with only surfactants such aspetroleum sulfonates and solubilizers in reservoir water or using thesame mixture with a polymer, but without separating and using the phasehaving the higher surfactant content followed by a polymer slugcontaining the fraction containing the lower sulfonate content as taughtby this invention.

The surfactant flood fluid of this invention can be used in the samemanner as similar fluids of the prior art. For instance, a preflush canbe introduced into an injection well followed by the surfactant fluid ofthis invention containing a higher concentration of sulfonates which isthe product of dissolving a small amount of polymer in a solution ofreservoir water containing surfactant and solubilizer, then allowing themixture to separate. In most cases the portion with the highestmono-sulfonate content is the lower phase, but depending on thedensities of the chemicals it may be the upper phase. Then where apolymer under pressure is injected after the surfactant fluid mixture,the process of this invention can be utilized, comprising injectingunder pressure a polymer slug containing the phase remaining which ismade up of a surfactant-brine-solubilizer-polymer mixture containing thelower sulfonate content.

Temperature, time and pressure conditions are not critical. Thetemperature is usually room temperature, but it should be less than 180°C. In the operation of this invention the pressure is generally low andmay range from atmospheric to reservoir pressure.

With the foregoing disclosure in mind, the following examples arepresented which will illustrate to those of ordinary skill in the artthe manner in which this invention is carried out. However, the exampleswhich follow are not to be construed as limiting the scope of theinvention in any way and the examples merely point out methods ofobtaining the greatest efficiency in use of the invention.

The experiments demonstrate that using the separated phase of thisinvention having low sulfonate content, resulting from mixing a smallamount of polymer with the water-surfactant-solubilizer and separatingthe phase with the lower sulfonate content to add to the polymer slugresults in higher percentages of enhanced recovery than found usingother flooding compositions.

EXAMPLE I

A Berea sandstone core was saturated with Salem reservoir brine andflooded with Salem Crude oil. The core was then water flooded with Saleminjection water. A surfactant flooding fluid was mixed comprising 1.8%STEPAN PETROSTEP® 465 petroleum sulfonate and 0.7% ALFONIC® 1412-Asolubilizer in Salem Injection water. This mixture was injected into thecore as the surfactant slug and displaced by 1000 ppm Kelzanpolysaccharide polymer followed by tap water. Kelzan is manufactured bythe Xanco division of Kelco Corporation. The core gave a tertiaryrecovery of 62.5%.

COMPARATIVE EXAMPLE IA

A Berea sandstone core was saturated with Salem reservoir brine andflooded with Salem Crude oil. The core was then water flooded with Saleminjection water. A surfactant flooding fluid was mixed comprising 1.8%STEPAN PETROSTEP® 465 petroleum sulfonate and 0.7% ALFONIC® 1412-Asolubilizer in Salem Injection water. To thisbrine-surfactant-solubilizer mixture was added 300 ppm NAFLO® Fpolyacrylamide. The polymer was allowed to mix in the surfactant fluidand the mixture allowed to separate. The time was not critical and mayrange from 10-1000 hours. In this example the separation occurred within1 day or about 24 hours. The mixing proceeded at room temperature andatmospheric pressure.

When the mixture had separated into two phases, the fraction with thehighest sulfonate content was separated for use as a surfactant fluid inthe tertiary or enhanced recovery. The remaining phase was mixed withthe 1000 ppm Kelzan polysaccharide slug. The surfactant was displaced bythe surfactant enriched polymer slug and this in turn by tap water. Whenthe core was displaced by this mixture, the core gave a tertiaryrecovery of 76%.

COMPARATIVE EXAMPLE IB

A Berea sandstone core was saturated with Salem reservoir brine andflooded with Salem Crude oil. The core was then water flooded with Saleminjection water. A surfactant flooding fluid was mixed comprising 1.8%STEPAN PETROSTEP® 465 petroleum sulfonate and 0.7% ALFONIC® 1412-Asolubilizer in Salem Injection water. To thisbrine-surfactant-solubilizer mixture was added 300 ppm NAFLO® Fpolyacrylamide. The polymer was allowed to mix in the surfactant fluidand the mixture allowed to separate. The time was not critical and couldrange from 10-1000 hours. In this example the separation occurred within1 day or about 24 hours. The mixing proceeded at room temperature andatmospheric pressure.

When the mixture had separated into two phases, the fraction with thehighest sulfonate content was separated for use as a surfactant fluid inthe tertiary or enhanced recovery. The remaining phase was mixed withthe 1000 ppm Kelzan polysaccharide slug. The surfactant was displaced bythe surfactant enriched polymer slug and this in turn by tap water. Whenthe core was displaced by this mixture, the core gave a tertiaryrecovery of 94.2%.

EXAMPLE II

A Berea sandstone core was saturated with Salem reservoir brine andflooded with Salem Crude oil. The core was then water flooded with Saleminjection water. A surfactant flooding fluid was mixed comprising 1%WITCO® TRS-40 and 0.8% WITCO® TRS-18 petroleum sulfonates and 0.7%ALFONIC® 1412-A solubilizer in Salem Injection water. This mixture wasinjected into the core as the surfactant slug and displaced by 1000 ppmKelzan polysaccharide polymer followed by tap water. The core gave atertiary recovery of 64.5%.

COMPARATIVE EXAMPLE IIA

A Berea sandstone core was saturated with Salem reservoir brine andflooded with Salem Crude oil. The core was then water flooded with Saleminjection water. A surfactant flooding fluid was mixed comprising 1%WITCO® TRS-40, 0.8% WITCO® TRS-18 petroleum sulfonates and 0.7% ALFONIC®1412-A solubilizer in Salem Injection water. To thisbrine-surfactant-solubilizer mixture was added 300 ppm NAFLO Fpolyacrylamide. The polymer was allowed to mix in the surfactant fluidand the mixture allowed to separate. The time was not critical and couldrange from 10-1000 hours. In this example the separation occurred within1 day or about 24 hours. The mixing proceeded at room temperature andatmospheric pressure.

When the mixture had separated in two phases, the fraction with thehighest sulfonate content was separated for use as a surfactant fluid ina tertiary or enhanced recovery. The surfactant was displaced by 1000ppm Kelzan polysaccharide followed by tap water. When the oil wasdisplaced by this mixture the core gave a tertiary recovery of 80.1%.

COMPARATIVE EXAMPLE IIB

A Berea sandstone core was prepared and water flooded as in Example II.A surfactant flooding fluid was mixed comprising 1% WITCO® TRS-40, 0.8%WITCO® TRS-18, petroleum sulfonates and 0.7% ALFONIC® 1412-A solubilizerin Salem injection water. 300 ppm NAFLO® F polyacrylamide was added tothis mixture and allowed to separate. The fraction with the highestsulfonate content was used as the surfactant slug. The other phase wasadded to the 1000 ppm Kelzan polysaccharide slug. The surfactant slugwas displaced by the sulfonate enriched polymer slug and this in turn bytap water. The tertiary displacement for this displacement was 99.3%.

The significant end point values for these examples are tabulated inTable I.

                  TABLE I                                                         ______________________________________                                        CORE DISPLACEMENT TESTS                                                              STEPAN ®  WITCO ®                                                     Surfactant    Surfactant                                                      I     IA      IB      II    IIA   IIB                                  ______________________________________                                        Initial Oil                                                                            73.0%   72.6%   66.6% 69.8% 72.4% 65.7%                              Saturation                                                                    Oil Satu-                                                                              43.4%   43.1%   39.7% 41.3% 45.6% 38.2%                              ration After                                                                  Water Flood                                                                   % Recovery                                                                             40.5%   40.6%   40.4% 40.8% 37.5% 41.9%                              by Water                                                                      Flood                                                                         Oil Satu-                                                                              16.3%   10.3%    2.3% 14.6%  9.0%  0.3%                              ration After                                                                  Chemical                                                                      Flood                                                                         % Recovery                                                                             77.7%   85.8%   96.5% 79.0% 87.5% 99.6%                              After Chemi-                                                                  cal Flood                                                                     % Recovery                                                                             62.5%   76.0%   94.2% 64.5% 80.1% 99.3%                              By Chemi-                                                                     cal Flood                                                                     ______________________________________                                    

The experiments demonstrate that using the separated phase, having thelower sulfonate content which remains after separating the highersulfonate containing fraction used as the surfactant slug, and enrichingthe polymer slug with it resulted in even greater percentages ofenhanced recovery than using the process described in Ser. No. 729,452alone.

What is claimed is:
 1. A process for enhanced hydrocarbon recoverycomprising injecting into a well a surfactant fluid comprising thefraction having the highest sulfonate content which separates aftersettling from a mixture of water, petroleum sulfonate surfactant,solubilizer and polymer and thereafter adding the remaining fraction ofsurfactant fluid which contains the lower sulfonate content to a polymerslug, injecting the polymer slug and forcing said high sulfonate contentsurfactant slug and subsequently the low sulfonate polymer slug throughthe formation and recovering said hydrocarbons.
 2. The process of claim1, wherein the polymer added to the surfactant fluid mixture is selectedfrom the group consisting of polyacrylamides, polysaccharides and anyhigh molecular weight polymer which tends to reduce the mobility of anaqueous surfactant mixture.
 3. The process of claim 2, wherein thepolymer added to the surfactant fluid is a polyacrylamide.
 4. Theprocess of claim 2, wherein the polymer added to the surfactant is apolysaccharide.
 5. The process of claim 3, wherein the polyacrylamide isNaflo F polyacrylamide.
 6. The process of claim 4, wherein the polymeris Kelzan polysaccharide.
 7. The process of claim 1, wherein thesurfactant fluid is made up of reservoir water with petroleum sulfonatesand solubilizers added for stability.
 8. The process of claim 7, whereinthe petroleum sulfonates are selected from the group consisting of allcommercial sulfonates.
 9. The process of claim 8 wherein the petroleumsulfonates are selected from the group consisting of WITCO® TRS-40,WITCO® TRS-18 and STEPAN PETROSTEP®
 465. 10. The process of claim 1wherein the polymer is present in the surfactant fluid in an amountwithin the range of 0.1 to 10% by weight based on the total weight ofsaid surfactant fluid.
 11. The process of claim 1 wherein the polymer ispresent in an amount of 50 to 500 ppm or 0.1% to 10% by weight and saidsurfactant fluid contains surfactant present in an amount in the rangeof 0.1% to 20.0% based on the weight of said fluid.
 12. The process ofclaim 1 wherein the polymer is present in amount of about 100 ppm to 300ppm.
 13. The process according to claim 1 wherein the time allowed fordissolving the polymer in the surfactant solution and allowingseparation is from 10 to 1000 hours.
 14. In a processcomprising:injecting into the well a surfactant fluid comprising about0.1% to about 20.0% of total solute by weight petroleum sulfonatesurfactant; about 0.1% to about 5% of total solute by weight solubilizerdispersed in the water; about 0.1 to 10% by weight polymer, wherein thesurfactant fluid formed is the product of dissolving the polymer in thewater-surfactant-solubilizer fluid, allowing the mixture to separate andseparating the fraction with the highest sulfonate content to use as thesurfactant fluid, the improvement comprising separating the remainingfraction which contains the lower sulfonate content to add to a polymerslug which is injected after the surfactant slug, forcing said highsulfonate content surfactant slug, and subsequently the low sulfonatecontent containing enriched polymer slug through the formation andrecovering said hydrocarbons.